1

DRAFT 

TECHNICAL/ECONOMIC PROFILES OF MAJOR 

PRODUCING COALBED METHANE BASINS IN THE 

UNITED STATES 

SAN JUAN BASIN 

Introduction 

The San Juan Basin covers approximately 22,000 square miles in southwestern 

Colorado and northwestern New Mexico, Figure 1. The basin extends across 

mountainous terrain of public property and tribal reservations. 

Figure 1. Areal Extent of the San Juan Basin1

The coal bed methane (CBM) resource within this basin is contained within the 

upper cretaceous age Fruitland and Menefee coals, Figure 2. 

 

1

 U.S. Geological Survey, National Oil and Gas Assessment (http://pubs.usgs.gov/fs/fs-147-02/) 
2
3

Figure 2. San Juan Basin Stratigraphic Column 

Source: Advanced Resources International, Incorporated 

The San Juan Basin’s Fruitland coals range from 3,100 feet deep (to the base of 

the formation) to 6,000 feet deep. The coals are shallowest in the central “fairway”, 

deepening to the north and south. Net Fruitland coal thickness ranges from 50 to 90 feet 

in the central and northern portions of the basin to 10 to 30 feet in the outlying areas. 
4

Individual coal beds are larger and more contiguous in the Fruitland fairway than the 

peripheral areas, especially to the southwest of the fairway.2

The San Juan Basin has been one of the longest-producing and profitable CBM 

basins in the world. The first well targeting CBM was drilled in 1977 by Amoco. By 

1991, 2,032 wells were producing 270 billion cubic feet (Bcf). As of the end of 2009, the 

CBM play in the basin is mature, having produced nearly 16 trillion cubic feet (Tcf) to 

date. The high productivity CBM wells in this basin provided the motivation for the 

expanded CBM play activity in the coal basins of the U.S and worldwide. 

The success of the basin is the result of favorable coal seam thickness, good 

permeability and gas content, existing over a large area. Development of the coals for 

methane was assisted by extensive drilling in previous decades into the gas-containing 

Pictured Cliffs sandstone below the coals, which resulted in an in-place infrastructure to 

handle the gas. 

Resource Potential 

The USGS estimates that San Juan Basin coal seams contain over 24 Tcf of CBM 

resources, of which the majority is contained within the Fruitland coal (98% of the total).3

Based on in-depth studies undertaken by Advanced Resources, the Fruitland coals in the 

basin are estimated to hold on the order of 46 Tcf of technically recoverable CBM 

resource. 

Development/Production History and Trends 

Well Drilling 

CBM well drilling in the San Juan Basin peaked in 2006, when 658 CBM wells 

were drilled, and has been steeply declining since. An estimated 300 CBM wells were 

drilled in 2009, down from 414 in 2008, Figure 3. 

Much of the early expansion in CBM well drilling was driven by development of 

the core area of the Fruitland coal “fairway.” Today, the well drilling in the basin is 

predominately in the southern and other extensions of the play. 

 

2

 U.S.G.S. Professional Paper, 1625-B Geologic Assessment of Coal in the Colorado Plateau: Arizona, 

New Mexico and Utah. Chapter Q. 2000 

3

 U.S. Geological Survey, National Oil and Gas Assessment (http://pubs.usgs.gov/fs/fs-147-02/) 
5

Figure 3. Coalbed Methane Well Drilling in the San Juan Basin 

0

100

200

300

400

500

600

700

1997 1999 2001 2003 2005 2007 2009

Wells Drilled/Year

Sources: IHS Inc. ( http://www.ihs.com/energy-solutions/index.htm), and HPDI, Inc. 

(http://www.hpdi.com/) 

Production 

CBM production from the San Juan Basin had been in a moderate decline since 

the late 1990s, where production approached 1 Tcf per year. San Juan Basin production 

has remained close to 800 Bcf/year in 2007 and 2008, Figure 4. 

Figure 4. Coalbed Methane Production in the San Juan Basin 

0

200

400

600

800

1,000

1,200

1997 1999 2001 2003 2005 2007 2009 (e)

Bcf/Year

Sources: IHS Inc., (http://www.ihs.com/energy-solutions/index.htm), HPDI, Inc. 

(http://www.hpdi.com/), and the Energy Information Administration 

(http://tonto.eia.doe.gov/dnav/ng/ng_prod_coalbed_s1_a.htm) 
6

Market/Access/Environmental Considerations 

Resource Access 

Based on the most recent federal lands resource characterization,4 an estimated 

50% of CBM resource in the San Juan Basin underlies federal lands. An estimated 5% of 

the CBM resource in the basin is off limits to all development and production, and 

another 14% is subject to federal leasing restrictions that limit development during 

certain months of the year. 

Market Access 

A well developed network of gathering systems and pipelines provide ready 

market access for San Juan Basin CBM Production. Much of the gas produced in the 

basin currently trades through the Blanco Hub and predominantly services demand in 

southern California. Although its business location is in northern New Mexico, the 

Blanco Hub is a primary provider of market center services to pipelines and producers 

located in southwestern Colorado part of the basin. Some of the gas produced in the basin 

is directed through the Waha area hubs. Due to its distance from the major gas market 

centers, the Blanco Hub has a negative basis differential relative to Henry Hub. 

Though it will originate in Northern Colorado, the Rockies Express pipeline could 

provide more profitable market access for San Juan Basin CBM by creating a direct route 

to major demand centers in the east. 

Environmental Considerations 

Some of the development challenges encountered in the basin include: (1) 

altitudes of 5,000–7,000 feet, (2) high produced water salinity necessitating disposal 

wells, (3) in a few reservoirs, desorbed methane contaminated with 4–6% carbon dioxide 

(CO2), (4) environmental concerns in a national forest, and (5) difficult access to remote 

locations. 

The quality of CBM produced water varies throughout the San Juan basin. In the 

northern areas, freshwater influx results in relatively high quality, low salinity produced 

 

4

 All characterizations of CBM resource potential underlying federal lands included in this report are based 

on U.S. Department of Interior, Bureau of Land Management, Scientific Inventory of Onshore Federal 

Lands' Oil and Gas Resources and the Extent and Nature of Restrictions or Impediments to Their 

Development — Phase II Cumulative Inventory, prepared by Advanced Resources International, 2006 

(http://www.blm.gov/epca/) 
7

water. The CBM produced water in the central areas of the Fruitland coal fairway can be 

brackish (total dissolved solids (TDS) levels of 20,000 ppm). However, in all areas, 95% 

of produced water is reinjected into deep disposal zones in the basin; the remainder is 

evaporated.5 

A final Environmental Impact Assessment (EIA) has recently been issued for the 

Northern (Colorado) portion of the basin, which could open up areas of the basin for new 

exploration and drilling.6 In April, 2010, the Bureau of Land Management (BLM) and 

conservation groups settled an eight-year dispute over a management plan for nearly 

10,000 natural gas wells in the basin.7

 

5

 Cox. D.O., Stevens, S.H., Water Disposal From Coalbed Methane Wells in the San Juan Basin, SPE 

Paper No. presented at the SPE Annual Technical Conference and Exhibition, 3-6 October 1993, Houston, 

TX. 

6

http://www.fs.fed.us/r2/sanjuan/projects/ea/nsjb/feis/feis.shtml 

7

http://www.huffingtonpost.com/2010/04/27/san-juan-basin-drilling-d_n_554337.html 
8

POWDER RIVER BASIN 

Introduction 

The Powder River Basin CBM play is located in northeastern Wyoming and 

southeastern Montana, Figure 5, consisting of thick coals of sub-bituminous rank. It is an 

elongated basin of trending from the northwest to the southeast, bounded by the Black 

Hills on the east and the Big Horn Mountains on the west. The CBM play covers 12,000 

square miles and encompasses parts of seven counties in two states. 

Figure 5. Outline and Location of the Powder River Basin 

Source: Advanced Resources International, Incorporated
9

The coalbed methane is contained in Tertiary-age Fort Union Formation coal seams, such 

as the Anderson, Wyodak, Big George and deeper coals (Figure 6). The main characteristic of 

the basin is the extraordinary thicknesses of individual seams; the record coal seam thickness 

reported in the United States is a 220 foot thick seam near Buffalo, Wyoming in the Wasatch 

formation (Eocene).8 Another distinguishing characteristic is the shallow depth of the coal seams 

in the basin; most of this resource is at a depth of 2,500 feet or less. 

Although the basin’s potential as a large CBM resource was recognized more than two 

decades ago, its low-rank coals discouraged development. By the mid-1990s however, activity 

increased rapidly as the geology and reservoir properties of the Powder River Basin CBM play 

were beginning to be understood. To date, an estimated 3.1 Tcf of CBM has been recovered 

from this basin. 

In summary, the factors favoring CBM production in the Powder River Basin are the 

thick coal seams, high permeability, shallow depths, and correspondingly low drilling and 

completion costs. Unfavorable characteristics are low-rank coals, low methane content of coals, 

water disposal, and problems with water rights. 

Resource Potential 

The USGS estimates that Powder River Basin coal seams contain over 14 Tcf of CBM 

resources, with the Upper Fort Union Formation containing 85% of the total (about 12.1 Tcf). 

Coalbed-gas resources of the Wasatch Formation were assessed at a mean of about 1.9 Tcf, and 

those in the Lower Fort Union-Lance were assessed at a mean of about 0.19 Tcf.9 

Advanced Resources estimates that Powder River Basin coal seams contain 78 Tcf of 

CBM resources in place.10 Under state-of-the-art technology, which can produce from multiple 

coal seams using a single well, an estimated 52 Tcf of CBM resources could be technically 

recovered. Over 92% of this resource exists in Wyoming and is concentrated in the Big George 

coal horizon, the largest and most regionally extensive of the multiple coals that exist in the 

basin. 

 

8

 Larsen, V.E.: "Preliminary Evaluation of Coalbed Methane Geology and Activity in the Recluse Area, Powder 

River Basin, Wyoming," Quarterly Review of Methane from Coalseams Technology (June 1989) , Nos. 3 and 4, 2-

10 

9

 U.S. Geological Survey, National Oil and Gas Assessment (http://pubs.usgs.gov/dds/dds-069/dds-069-c/) 

10 Kuuskraa, V., Van Leeuwen, T. Multi-Seam Well Completion Technology Implications for Powder River Basin 

Coal Bed Methane Production: 2008 Update. Contract No. DE-AC26-04NT41817, 2008 
10

Figure 6. Powder River Basin Stratigraphic Column 

Source: U.S. Geological Survey 

Development/Production History and Trends 

Well Drilling 

After reaching a peak of over 3,500 wells drilled in 2001, well drilling in the Powder 

River basin has been between 2,000 and 2,500 wells per year for the past 6 years, Figure 7. 
11

Figure 7. Coalbed Methane Well Drilling in the Powder River Basin 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

1997 1999 2001 2003 2005 2007 2009

Wells Drilled/Year

Sources: IHS Inc. ( http://www.ihs.com/energy-solutions/index.htm), and HPDI, Inc. 

(http://www.hpdi.com/) 

Production 

Production from the Powder River Basin increased rapidly between 1997 and 2020, 

growing from below 100 Bcf/year to over 300 Bcf/year over this time period, Figure 8. 

Production grew more slowly between 2001 and 2006 as produced water issues limited new 

drilling. As drilling resumed, production increased again and in 2008 was 572 Bcf/year 

Market/Access/Environmental Characteristics 

Resource Access 

Based on the most recent federal lands resource characterization, an estimated 43% of 

CBM resource in the Powder River Basin underlies federal lands. Of this, an estimated 6% of 

the CBM resource in the basin is off limits to all development and production and another 21% is 

subject to federal leasing restrictions that limit development during certain months of the year. 
12

Figure 8. Coalbed Methane Production in the Powder River Basin 

0

100

200

300

400

500

600

700

1997 1999 2001 2003 2005 2007 2009 (e)

Bcf/Year

Sources: IHS Inc., (http://www.ihs.com/energy-solutions/index.htm), HPDI, Inc. 

(http://www.hpdi.com/), and the Energy Information Administration 

(http://tonto.eia.doe.gov/dnav/ng/ng_prod_coalbed_s1_a.htm) 

Market Access 

The Cheyenne Hub originally began operations in 2000 to support the growing need for 

natural gas transportation out of the Powder River Basin and to provide trading services for 

eastern Wyoming and northern Colorado area producers and other market makers. However, as 

production from the basin continued to increase, access to markets for Powder River Basin CBM 

was limited by a lack of pipeline capacity and unfavorable basis differentials. In November 2009, 

Kinder Morgan completed the Rockies Express Pipeline, providing Rocky Mountain gas access 

to Midwestern markets. This pipeline is one of the largest pipelines ever constructed in the 

United States; stretching 1,679 miles from northwestern Colorado to eastern Ohio, capable of 

transporting 1.8 Bcf per day. 

Environmental Considerations 

The volume of water produced in association with CBM gas production in the Powder 

River Basin is significant.11 Depending on quality, this water is either surface discharged, 

reinjected, or sometimes put to other beneficial uses. For example, water from the Fort Union 

 

11 U.S. Department of Energy, National Energy Technology Laboratory, The Economics of Powder River Basin 

Coalbed Methane Development, Prepared by Advanced Resources International, Inc., January 2006 

(http://www.fossil.energy.gov/programs/oilgas/publications/coalbed_methane/PRB_Coalbed_Methane_Developmen

t.html) 
13

Formation, a major CBM formation, supplies municipal water to the city of Gillette. TDS levels 

in the water produced from these coal beds often meet the water quality criteria for drinking 

water. 

Nonetheless, potential environmental impacts from CBM operations can be experienced, 

and include: reduced flow or loss of domestic water wells, mortality and reduced growth and 

vigor of vegetation, erosion, soil compaction, and loss of topsoil.12 Nearby farming and ranching 

operations that rely on source water for irrigation and water operations are particularly sensitive 

to increases in salinity and sodicity, if and/or when they occur. Waters with TDS levels over 500 

mg/L and sodium adsorption ratios (SARs) over 6 (characteristics often associated with CBM 

waters) have decreasing utility for cropland irrigation and other agricultural and wildlife uses. In 

addition, many citizens in the Powder River Basin are concerned about the potential loss of 

drinking water. 

 

12 http://www.blm.gov/wy/st/en/info/NEPA/bfodocs/prb_eis.html 
14

APPALACHIAN BASIN 

Introduction 

The Mississippian and Pennsylvanian aged coals of the Appalachia Basin are located 

over a large geographic area in Virginia, West Virginia, Pennsylvania, Ohio, Kentucky, and 

Tennessee, Figure 9. The basin is often considered in two distinct parts: 

• The Northern Appalachian basin (Figure 9a), occupying approximately 44,000 sq miles 

in West Virginia, Pennsylvania, Ohio, Kentucky, and Maryland. Residing from outcrop 

to 2,000-feet deep, the Pennsylvanian Age coals in the basin are shallower than its 

counterparts to the south, the Central Appalachian and Black Warrior basins. The 

important seams in the Northern Appalachian basin lie above the Pottsville formation, 

which contains the seams of the Central Appalachian and Warrior basins.13

• The narrow 23,000-square mile Central Appalachian basin (Figure 9b), which extends 

over portions of West Virginia, Virginia, Kentucky, and Tennessee in a northeast to 

southwest direction with the area of most promise and highest gas content near its 

center.14The coals are primarily commercially productive in Southwestern Virginia and 

Southern West Virginia in the Pocahontas Basin. 

Coalbed development in the Central Appalachian Basin occurred quickly after 2000. 

CBM development in the Northern Appalachian Basin has lagged that in many other areas 

because of insufficient reservoir knowledge, inadequate well completion techniques, and 

unresolved CBM ownership issues revolving around whether the gas is owned by the mineral 

owner or the oil and gas owner. 

Because of the extensive mining in the area, the coals are under-pressured and produce 

less water than many other basins, though the chloride content and total solids content tend to be 

higher. Because the coals are shallower, more under pressured, and generally lower rank, their 

gas content is lower at 150–200 scf/ton. 

 

13 Byrer, C.W., Mroz, T.H., and Covatch, G.L.: "Coalbed Methane Production Potential in U.S. Basins," Journal of 

Petroleum Technology (July 1987) 39, No. 7, 821-834 

14 Hunt, A.M. and Steele, D.J.: "Coalbed Methane Development in the Northern and Central Appalachian Basins--

Past, Present and Future," Proc., Coalbed Methane Symposium, Tuscaloosa, Alabama (May 1991) 127. 
15

Figure 9a. Northern Appalachian Basin15

Figure 9b. Central Appalachian Basin 

 

15 Limerick, Samuel H., Coalbed Methane in the United States: A GIS Study, Search and Discovery Article #10066 

(2004), adapted from a poster presentation at AAPG Annual Meeting, Dallas, Texas, April 18-21, 2004) 
16

 In the Central Appalachian Basin, mining in the basin has tended to reduce the amount of 

water that needs to be removed to achieve gas production. Gas content and permeabilities tend to 

be similar to the Warrior basin (see below), but both properties are higher than the Northern 

Appalachian. The Pennsylvanian Age coal generally ranges from high-A to low-volatile 

bituminous, a higher rank than accorded its northern counterpart. 

A generalized stratigraphic column of the Central Appalachian Basin is shown in Figure 

10. 

Figure 10. Generalized Stratigraphic Column -- Central Appalachian Basin 

Resource Potential 

In 2004, the USGS estimated that 8.4 Tcf of CBM was technically recoverable in the 

West Dunkard and Pocahontas formations in the Appalachian basin.16 These are the only two 

coal bed formations that the USGS has assessed to date in the basin, with the Pocahontas 

formation containing 3.6 Tcf, and the West Dunkard containing about 4.8 Tcf. Advanced 

 

16 U.S. Geological Survey, National Oil and Gas Assessment (http://pubs.usgs.gov/of/2004/1272/) 
17

Resources estimates that 9.3 Tcf is technically recoverable from these formations, considered 

over a comparable geographical area. 

Development/Production History and Trends 

Well Drilling 

Drilling in the Appalachian Basin was steady at between 250 and 300 wells per year 

between 1997 and 2003, with one little increase in 2001. Beginning in 2004, well drilling began 

to increase, Figure 11, peaking in 2006 at over 600 wells. Most of the drilling is in the Central 

Appalachian Basin. Drilling is still expected to remain high in the basin even as the CBM 

resource matures. 

Figure 11. Appalachian Basin Well Drilling 

0

100

200

300

400

500

600

700

1997 1999 2001 2003 2005 2007

Wells Drilled/Year

Sources: IHS Inc. ( http://www.ihs.com/energy-solutions/index.htm), and HPDI, Inc. 

(http://www.hpdi.com/) 

Production 

In conjunction with increased well drilling after 2003, production also has seen a steady 

rise, Figure 12. Production reached 140 Bcf/year in 2008, up from 40 Bcf/year in 1997. As 

drilling continues, production is expected to continue to rise, again with the focus of activity in 

the Central Appalachian Basin. 
18

Figure 12. Appalachian Basin Production 

0

20

40

60

80

100

120

140

160

1997 1999 2001 2003 2005 2007

Bcf/Year

Sources: IHS Inc., (http://www.ihs.com/energy-solutions/index.htm), HPDI, Inc. 

(http://www.hpdi.com/), and the Energy Information Administration 

(http://tonto.eia.doe.gov/dnav/ng/ng_prod_coalbed_s1_a.htm) 

Market/Access/Environmental Characteristics 

Resource Access 

Only 2% of the acreage in the Appalachian Basin is classified as federal lands, and 

presumably, about 2% of the resource potential underlies federal lands. Overall, about 1% of the 

total acreage is inaccessible and 1% is accessible with restrictions on drilling. A small portion of 

the resource also underlies state government lands. 

Market Access 

The Appalachian Basin is favorably located near major pipelines transporting gas to 

northeastern markets. The Basin is also in close proximity to the Dominion South Point Hub. 

Producers typically benefit from a negligible or even slightly positive basis differential. 

Environmental Considerations 

Like other Eastern basins, the Appalachian basin coal seams generally produce waters 

that have higher concentrations of chlorides and dissolved solids than produced water from most 

western basins, which preclude them from most beneficial uses. The produced water quality in 

the basin can be highly variable, but typically contains TDS levels above 10,000 ppm TDS, and 

can be high in metals, sulfur and arsenic.
19

RATON BASIN 

Introduction 

The Raton Basin is located in the southeastern corner of Colorado and spans into the 

northeastern corner of New Mexico, Figure 13. It is one of the smallest of the coal basins, 

covering 2,200 square miles extending from the northeastern New Mexico border and the 

southeastern Colorado. The basin is bounded on the north by the Wet Mountains and bounded on 

the west by the Sangre de Cristo Mountains. Altitudes of 9,000 feet are reached in the basin. 

Figure 13. Raton Basin17

Late Cretaceous and Paleocene coals in the Raton basin are found in the Vermejo and 

Raton formations. Below the Vermejo is the Trinidad sandstone. The low-volatile bituminous 

coal exists in seams of 14-foot maximum thickness, averaging 3 to 8 feet in the Vermejo 

formation and 12-foot maximum thickness in the Raton formation; generally the seams are thin, 

 

17 U.S. Geological Survey, National Oil and Gas Assessment (http://pubs.usgs.gov/fs/2005/3027/508fs3027.html) 
20

but they may be numerous for a given well. As many as 40 seams exist in these formations, with 

a cumulative thickness of 90 feet from outcrop to a depth of 4,000 feet. Most seams are lenticular 

and discontinuous.18 The generalized stratigraphy of Cenozoic and Mesozoic units in Raton 

basin is shown in Figure 14. 

Figure 14. Generalized Stratigraphic Column, Central & Northern Raton Basin19

 

18 Stevens, S.H.: "Raton Basin-Colorado and New Mexico," Quarterly Review of Methane from Coalseams 

Technology (August 1993) 11, No. 1, 33-36. 

19 Worrall, John, “Preliminary Geology of Oakdale Field, Northwest Raton Basin, Huerfano County, Colorado,” 

Adapted from Transactions, AAPG Southwest Section Convention, Ruidoso, New Mexico, June 6-8, 2002 
21

Resource Potential 

A 2004 USGS assessment of undiscovered continuous resources estimates that 1.59 Tcf 

of recoverable resources are contained in the Raton (0.61 Tcf) and Vermejo (0.98) Tcf) 

Formation coals in the Raton basin.20 Advanced Resources estimates 8.2 Tcf is technically 

recoverable from a similar geographical area.

Development/Production History and Trends 

Well Drilling 

Drilling in the Raton Basin increased steadily from 1998 to 2007, peaking at 570 wells, 

after which drilling has started to decline (Figure 15). 

Figure 15. Raton Basin Well Drilling 

0

100

200

300

400

500

600

1997 1999 2001 2003 2005 2007

Wells Drilled/Year

Sources: IHS Inc. ( http://www.ihs.com/energy-solutions/index.htm), and HPDI, Inc. 

(http://www.hpdi.com/) 

Production 

Similarly, production in the Raton Basin increased steadily from 1998 to 2007, peaking at 

over 140 Bcf year (Figure 16), a level that should be maintained into the foreseeable future. 

 

20 U.S. Geological Survey, National Oil and Gas Assessment (http://pubs.usgs.gov/fs/2005/3027/508fs3027.html) 
22

Figure 16. Raton Basin Production 

0

20

40

60

80

100

120

140

160

1997 1999 2001 2003 2005 2007

Bcf/Year

Sources: IHS Inc., (http://www.ihs.com/energy-solutions/index.htm), HPDI, Inc. 

(http://www.hpdi.com/), and the Energy Information Administration 

(http://tonto.eia.doe.gov/dnav/ng/ng_prod_coalbed_s1_a.htm) 

Market/Access and Environmental Characteristics 

Resource Access 

A significant but unquantified portion of the CBM resource in the Raton Basin underlies 

federal lands, some of which is inaccessible, and some of which is accessible under development 

restrictions. 

Market Access 

Traditionally constrained in terms of pipeline access to gas markets, in 2005, Colorado 

Interstate Gas Company (CIG), a subsidiary of El Paso Corporation, constructed a pipeline to 

expand the then existing pipeline system in the Raton Basin and extend transportation to the 

panhandle of Oklahoma. Another expansion, in 2008, provides approximately 130 million cubic 

feet per day (MMcf/d) of additional capacity from the Las Animas County area northward along 

the Front Range of Colorado to the Cheyenne Hub. 

Environmental Considerations 

Environmental and development challenges encountered in the Raton basin are similar to 

those in the San Juan basin, including the high altitude of the basin, the sometimes high produced 

water salinity necessitating disposal wells, environmental concerns related to development on 

federal land, and difficult access to remote locations. 
23

However, the coal seams of the Vermejo and Raton formations often produce water that 

can meet federal water quality criteria for drinking water. The underlying sandstone beds within 

the Vermejo and Raton formations, as well as intrusive dikes and sills, also contain water of that 

meets the drinking water quality criteria. 
24

BLACK WARRIOR BASIN 

Introduction 

The CBM industry began in the Black Warrior Basin of Alabama, and has been the 

source of much of the information and technology that has defined this industry. Early research 

from the Gas Research Institute’s (GRI) Rock Creek facility and field data from the many 

companies in the basin made the process viable there, especially for multiple, thin seams that are 

often individually only marginally profitable. 

Coal mining in the basin for over 100 years provided a source of geologic and 

engineering data that gave impetus to early CBM development. Much of this development 

original was motivated by the fact that the coal mines in the area have experienced safety 

problems throughout the history of mining there because coals in the basin tend to be gassy, and 

the methane must be degassed in areas before the coal can be mined. 

Methane degasification in advance of underground mining began in the early 1970s in the 

basin, and in the late 1970s and early 1980s, concerted efforts to improve mine safety conditions 

in deeply buried coal beds by degasification prior to and during mining operations was initiated. 

At first, vertical ventilation holes were drilled into the Blue Creek coal bed in Alabama, and the 

gas that was produced from coal beds in advance of mining, or from gob wells drilled into old 

works after mining, and was vented into the atmosphere 

The first permit to drill a CBM well for commercial production in the Black Warrior 

Basin was issued in 1981. The CBM industry in the basin was centered along a Tuscaloosa-toBirmingham axis, driven primarily by an infrastructure of service companies and accessible 

pipelines already in place to serve conventional natural production in the basin dating back to 

1953. In 1983, the Rock Creek research site was established by GRI, followed by the 

establishment of the Eastern Region Coalbed Methane Resource Center in 1985 at the University 

of Alabama. From this, the industry grew rapidly in the basin as the decade of the 1980s 

progressed, creating a boom atmosphere locally in the midst of an oil and gas industry depression 

nationwide. 

The Black Warrior Basin covers an area of about 23,000 square miles in Alabama and 

Mississippi (Figure 17). The basin is approximately 230 miles long from west to east and 

approximately 188 miles long from north to south. Coalbed methane production in Alabama is 
25

limited to the bituminous coalfields of west-central Alabama, primarily in Jefferson and 

Tuscaloosa Counties.21

Figure 17. Black Warrior Basin22

Coal seams in the basin from which methane is commercially produced range in depth 

from 500 feet in the Cobb seams to 4,500 feet in the Black Creek seams. However, the most 

productive depths are at about 1,500 to 3,000 feet. Individual seam thicknesses run from 1 foot 

or less to 8 feet with multiple seams occurring over a 1,000-foot interval. Net thickness of coal 

seams in any well may reach a maximum of 20–30 feet. 23

The coal in Alabama occurs in the Pottsville formation of lower Pennsylvanian Age rock. 

Four main coal groups occur in the Pottsville formation: Cobb, Pratt, Mary Lee, and Black Creek 

(Figure 18). The coal groups outcrop in the northern part of the basin. Additionally, a later 

interest has been shown in the Gwin group above the Cobb and the J-Interval below Black 

Creek. Rank of the coals is medium- to high-volatile bituminous, the Black Creek group being of 

 

21 "Raton Basin, Colorado and New Mexico," Quarterly Review of Methane from Coalseams Technology (March 

1990) 7, No. 3, 6-7. 

22 Limerick, Samuel H., Coalbed Methane in the United States: A GIS Study, Search and Discovery Article #10066 

(2004), adapted from a poster presentation at AAPG Annual Meeting, Dallas, Texas, April 18-21, 2004) 

23 "Raton Basin, Colorado and New Mexico," Quarterly Review of Methane from Coalseams Technology (March 

1990) 7, No. 3, 6-7. 
26

higher rank. The coals generally have low ash content, low sulfur content, and high methane 

content, on the order of 96%, and there are negligible amounts of carbon dioxide or nitrogen 

present 

Figure 18. Generalized Stratigraphic Column – Black Warrior Basin24

 

24 Pashin, J. C., 2005, Coalbed methane exploration in thrust belts: experience from the southern Appalachians, 

USA: Tuscaloosa, Alabama, University of Alabama, College of Continuing Studies, 2005 International Coalbed 

Methane Symposium Proceedings, paper 0519, 14 p. 
27

Resource Potential 

A 2002 USGS assessment of undiscovered continuous resources estimates that over 7.0 

Tcf of recoverable resources are contained in the Black Warrior Basin.25 Advanced Resources 

estimates that 5.1 Tcf is technically recoverable from a comparable area. 

Development/Production History and Trends 

Well Drilling 

Drilling in the Black Warrior Basin increased steadily from 1997 to 2006, peaking at 

about 430 wells, after which drilling started to decline (Figure 19), though drilling is still 

expected to remain relatively high in the basin. . 

Figure 19. Black Warrior Basin Well Drilling 

0

50

100

150

200

250

300

350

400

450

1997 1999 2001 2003 2005 2007

Wells Drilled/Year

Sources: IHS Inc. ( http://www.ihs.com/energy-solutions/index.htm), and HPDI, Inc. 

(http://www.hpdi.com/) 

Production 

Production in the Black Warrior Basin has remained in the 110 to 120 Bcf per year range 

consistently from 1997 to 2006 (Figure 20), though it may be difficult to continue to sustain that 

level for long into the foreseeable future. . 

 

25 U.S. Geological Survey, National Oil and Gas Assessment (http://pubs.usgs.gov/fs/2004/3092/fs2004-3092.html) 
28

Figure 20. Black Warrior Basin Production 

80

90

100

110

120

130

140

1997 1999 2001 2003 2005 2007

Bcf/Year

Sources: IHS Inc., (http://www.ihs.com/energy-solutions/index.htm), HPDI, Inc. 

(http://www.hpdi.com/), and the Energy Information Administration 

(http://tonto.eia.doe.gov/dnav/ng/ng_prod_coalbed_s1_a.htm) 

Market/Access/Environmental Characteristics 

Resource Access 

Similar to the Appalachian basin, about 4% of the acreage in the Black Warrior basin is 

classified as federal lands, with about 2% inaccessible to leasing. A small portion of the resource 

also underlies state government lands. 

Market Access Issues 

Similar to the Appalachian basin, the Black Warrior basin is favorably located near major 

pipelines transporting gas from the Gulf Coast to northeastern markets, mostly through the 

dominant Henry Hub. 

Environmental 

A significant factor in establishing the process in the Black Warrior Basin has been the 

ground-level treatment and disposal of produced waters. Even though the produced water quality 

does not meet drilling water standards, typically with TDS levels in excess of 30,000 ppm, the 

lack of suitable formations to dispose of produced waters, required that processes be developed 

to treat and surface discharge the produced water. Technology demonstrations and cooperation 

with government, along with close environmental monitoring, made this successful. 
29

UINTA-PICEANCE BASINS 

Introduction 

Uinta-Piceance Basins are located in northwestern Colorado and northeastern Utah. The 

Douglas Creek Arch separates the Piceance Basin from the Uinta Basin. The Wasatch Plateau is 

included in this province, Figure 21 

Figure 21. Unita-Piceance Basin26

The Piceance basin in western Colorado is an elliptically shaped basin divided by the 

Colorado River into one-third of the area south of the river (Figure 22). It contains coal of Late 

Cretaceous Age that underlies 6,570 square miles. The Uinta Basin of northeastern Utah and 

northwestern Colorado is a westward extension of the Piceance basin, where the best-tested field 

in the basin has been the Book Cliffs field. 

 

26 U.S. Geological Survey, National Oil and Gas Assessment (http://pubs.usgs.gov/fs/fs-0026-02/fs-0026-02.html) 
30

Figure 22. Piceance Basin27

 The coal in the Piceance basin is gassy with methane contents ranging from 440 to 570 

scf/ton. Individual seams are 50 feet thick near Rifle, Colorado. Net thicknesses of seams in 

single wells are 120 feet in the south and 250 feet in the northeast part of the basin. Three 

primary coal groups exist in the Mesaverde group: Black Diamond, Cameo, and Coal Ridge. The 

Black Diamond coal group is restricted mostly to the northern one-half of the basin, the Cameo 

group across the entire basin, and the Coal Ridge group about one-fourth of the basin.28

 In the Unita basin (Figure 23), in the Book Cliffs field, Upper Cretaceous, Mesaverde 

group coals are the main targets, where cores from test wells were analyzed to have a gas content 

of 443 scf/ton; 25 mines exist in eight coal beds.29 The Ferron coals within the Ferron sandstone 

 

27 Limerick, Samuel H., Coalbed Methane in the United States: A GIS Study, Search and Discovery Article #10066 

(2004), adapted from a poster presentation at AAPG Annual Meeting, Dallas, Texas, April 18-21, 2004) 

28 Tremain, C.M.: "Coalbed Methane Development in Colorado," Information Series 32, Colorado Geological 

Survey, U.S. Dept. of Natural Resources (September 1990). 

29 Gloyn, R.W. and Sommer, S.N.: "Exploration for Coalbed Methane Gains Momentum in Uinta Basin," Oil and 

Gas Journal (May 1993) 91, No. 22, 73-76. 
31

are the main targets in the Drunkard’s Wash field. The Ferron coals range from 1,200–3,400 feet 

in depth, with an average depth of 2,400 feet. These are high-volatile, B bituminous coals.30

Figure 23. Uinta Basin31

 Although thick seams and good gas content are characteristics of the basin, the coal is 

deep. Permeabilities that fall below 1 md in the northeastern part of the basin do not provide the 

 

30 Burns, T.D. and Lamarre, R.A.: "Drunkards Wash Project: Coalbed Methane Production from Ferron Coals in 

East-Central Utah," paper 9709 presented at the 1997 International Coalbed Methane Symposium, Tuscaloosa, 

Alabama, 12-16 May. 

31 Limerick, Samuel H., Coalbed Methane in the United States: A GIS Study, Search and Discovery Article #10066 

(2004), adapted from a poster presentation at AAPG Annual Meeting, Dallas, Texas, April 18-21, 2004) 
32

natural fracture network for commercial flow rates of gas. In the southeast part of the basin, the 

permeabilities improve because of structural deformations that have left the rock fractured. In the 

southeast, the over-pressured nature of the coal improves gas content. Overall, however, the 

depth of the basin gives a low permeability, which is its greatest impediment to development. 

Resource Potential 

A 2002 USGS assessment of undiscovered continuous resources estimates that nearly 2.4 

Tcf of recoverable resources are contained in the Unita-Piceance basin.32 Advanced Resources 

estimates that 11.3 Tcf is technically recoverable. 

Development/Production History and Trends 

Well Drilling 

Drilling in the Unita-Piceance basins peaked in 2001 at 170 wells, after which drilling 

went into sharp decline until 2005, where it appears to be leveling off (Figure 24). 

Figure 24. Unita-Piceance Basin Well Drilling 

0

50

100

150

200

1997 1999 2001 2003 2005 2007

Wells Drilled/Year

Sources: IHS Inc.( http://www.ihs.com/energy-solutions/index.htm), and HPDI, Inc. 

(http://www.hpdi.com/) 

Production 

Production in the Unita-Piceance basin peaked at 113 Bcf in 2002, following the trend in 

drilling. Production declined to about 70 Bcf in 2005, where it appears to be leveling off (Figure 

25). 

 

32 U.S. Geological Survey, National Oil and Gas Assessment (http://pubs.usgs.gov/fs/fs-0026-02/fs-0026-02.html) 
33

Figure 25. Unita-Piceance Basin Production 

0

20

40

60

80

100

120

1997 1999 2001 2003 2005 2007

Bcf/Year

Sources: IHS Inc., (http://www.ihs.com/energy-solutions/index.htm), HPDI, Inc. 

(http://www.hpdi.com/), and the Energy Information Administration 

(http://tonto.eia.doe.gov/dnav/ng/ng_prod_coalbed_s1_a.htm) 

Market/Access and Environmental Characteristics 

Resource Access 

Based on the most recent federal lands resource characterization, an estimated 67% of 

CBM resource in the Unita and Piceance basins underlies federal lands. An estimated 16% of 

the CBM resource is off limits to all development and production and another 41% is subject to 

federal leasing restrictions that limit development during certain months of the year. 

Market Access 

The addition of a new natural gas market center, the White River Hub in western 

Colorado (owned by a partnership between Enterprise Products Partners, LP and Questar Gas ), 

now provides natural gas producers in the Piceance and Uinta basins better access to the multiple 

intrastate and interstate pipelines that now serve the expanding production fields located within 

the surrounding area. 

Environmental Considerations 

The Blackhawk Formation and the Ferron coals often meet federal drinking water 

criteria. For example, groundwater from the Blackhawk Formation taken at can have TDS levels 

below 10,000 mg/L. Castlegate Field coal beds have published TDS levels of 5,000 mg/L in 

production waters. Water at depth in the Piceance Basin appears to be of poor quality. 
34

CHEROKEE/FOREST CITY 

Introduction 

The Western Interior Coal Region comprises three coal basins, the Arkoma (discussed 

separately), the Cherokee, and the Forest City Basins, and encompasses portions of Arkansas, 

Oklahoma, Kansas, Missouri, Nebraska, and Iowa. The Cherokee Basin begins near the 

Oklahoma-Kansas-Missouri border and extends northward along the Kansas-Missouri border 

(Figure 26). The basin is part of the Cherokee Platform Province, which covers approximately 

26,500 square miles in Oklahoma, Kansas, and Missouri. The Forest City Basin covers about 

47,000 square miles in Iowa, Kansas, Missouri, and Nebraska. 

Figure 26. Cherokee Basin33

 

33 Limerick, Samuel H., Coalbed Methane in the United States: A GIS Study, Search and Discovery Article #10066 

(2004), adapted from a poster presentation at AAPG Annual Meeting, Dallas, Texas, April 18-21, 2004) 
35

The geologic framework and many of the characteristics pertaining to coalbed gas are the 

same for both the Cherokee Platform and Forest City Basins. The big difference is that more 

development of coalbed gas has taken place in the Cherokee Platform, and more data are 

available for better assessing the recoverable coalbed gas potential. 

The thickest coal seams in the Cherokee Platform are assigned to the Middle 

Pennsylvanian (Desmoinesian) Cherokee Group, which varies in thickness from 300 to 500 feet. 

The main coal beds in the basin, is ascending order, are Riverton, Rowe, Weir-Pittsburg, 

Mineral, Fleming, Croweburg, Bevier, and Mulky. The Riverton, Weir-Pittsburg, Bevier, and 

Mulky are the thickest, and the Weir-Pittsburg seam can be as much as 5 ft thick.34,35 

Commercial production in this basin is relatively recent. In a manner similar to the 

Arkoma basin (see below), low water production rates and high permeability encourage 

commercial development of the shallow seams (600–1,200 feet deep). Wells were first drilled to 

develop the coal resource in 1990, although conventional gas-containing-coal gas was produced 

commercially many years before targeting the coals. 

In the Forest City Basin, coal-bearing strata are present in the Pennsylvanian Atokan and 

Desmoinesian Series. In all four States, the coals are assigned to the Riverton Formation and the 

Cherokee, Marmaton, and Pleasanton Groups. The coal beds are relatively widespread and 

commonly too deep to mine. Drill holes indicate that the cumulative coal thickness may be as 

much as 22 feet, and individual beds may be as thick as 10 feet. However, many of the beds are 

less than 2 feet thick, requiring more expensive, multiple-seam completions for commercial 

production. 

Resource Potential 

The somewhat dated 1995 USGS assessment of undiscovered continuous resources 

estimates that nearly 2.4 Tcf of recoverable resources are contained in the Cherokee/Forest City 

basins.36 Advanced Resources estimates that 2.5 Tcf is technically recoverable from a similar 

geographical area.

 

34 Schwochow, S.D. (ed.): "Cherokee Basin, Kansas and Oklahoma," Quarterly Review of Methane from Coalseams 

Technology (April 1992) 9, Nos. 3 and 4, 5. 

35 Stevens, S.H. and Sheehy, L.D.: "Western Interior Coal Region (Arkoma, Cherokee, and Forest City Basins)," 

Quarterly Review of Methane from Coalseams Technology (August 1993) 11, No. 1, 43-48. 

36 U.S. Geological Survey, National Oil and Gas Assessment 

(http://energy.cr.usgs.gov/oilgas/noga/assessment_updates_2008.html) 
36

Development/Production History and Trends 

Well Drilling 

Drilling in the Cherokee/Forest City basins peaked in 2004 at over 400 wells, after which 

in went into sharp decline (Figure 27). 

Figure 27. Cherokee/Forest City Basin Well Drilling

0

50

100

150

200

250

300

350

400

450

1997 1999 2001 2003 2005 2007

Wells Drilled/Year

Sources: IHS Inc.( http://www.ihs.com/energy-solutions/index.htm), and HPDI, Inc. 

(http://www.hpdi.com/) 

Production 

Production in the Cherokee/Forest City basins has continued to increase, surpassing 60 

Bcf in 2008 (Figure 28). 

Figure 28. Cherokee/Forest City Basin Production 

0

10

20

30

40

50

60

70

1997 1999 2001 2003 2005 2007

Bcf/Year

Sources: IHS Inc., (http://www.ihs.com/energy-solutions/index.htm), HPDI, Inc. 

(http://www.hpdi.com/), and the Energy Information Administration 

(http://tonto.eia.doe.gov/dnav/ng/ng_prod_coalbed_s1_a.htm) 
37

Market/Access/Environmental Characteristics 

Resource Access 

Most of the land in the Cherokee and Forest City Basin area is privately owned. 

Market Access 

Also, the Cherokee/Forest City Basin area would be an advantageous CBM production 

location because it currently has a network of pipelines in place to transport the gas produced.

Environmental Considerations 

There are plenty of recognized zones for disposing of waters that are produced by the 

extraction of the CBM in these basins. Initial water rates from a individual coal varies from 1 to 

over 500 barrels a day. Multiple seam completion varies from a mist to over 1,000 barrels a day. 

The water quality is generally salty to slightly salty throughout most of the basin. The mostly 

undeveloped Forest City basin is anticipated to have similar characteristics.
38

ARKOMA BASIN 

Introduction 

The Arkoma Basin covers about 13,500 square miles along the border of central 

Arkansas and Oklahoma (Figure 29). The east-to-west trending basin is about 250 miles long and 

20 to 50 miles wide. In Arkansas, the province is bounded on the north by the Ozark Uplift and 

in Oklahoma it is bounded on the north by the Cherokee Platform. 

Figure 29. Arkoma Basin37

The three most important coals in the Oklahoma part of the basin are the Hartshorne, 

Stigler, and Secor. It has been estimated that 10 individual seams that are each 1–7 feet thick 

exist in the Oklahoma part of the basin. The best gas content is reported to be on the order of 700 

scf/ton at a 3,000-foot depth in Le Flore County. The Hartshorne coal seam is the main target at 

 

37 Limerick, Samuel H., Coalbed Methane in the United States: A GIS Study, Search and Discovery Article #10066 

(2004), adapted from a poster presentation at AAPG Annual Meeting, Dallas, Texas, April 18-21, 2004) 
39

600–1,400 foot depth, and with good permeability of 3–30 md. Coals in the basin are of 

Pennsylvanian Age. 38

Resource Potential 

The somewhat dated 1995 USGS assessment of undiscovered continuous resources 

estimates that over 2.6 Tcf of recoverable CBM resources are contained in the Arkoma basin.39

Advanced Resources estimates that 6.7 Tcf is technically recoverable from a similar 

geographical area. 

Development/Production History and Trends 

Well Drilling 

Drilling in the Arkoma basin peaked in 2004 at nearly 400 wells (Figure 30). 

Figure 30. Arkoma Basin Well Drilling 

0

50

100

150

200

250

300

350

400

450

1997 1999 2001 2003 2005 2007

Wells Drilled/Year

Sources: IHS Inc.( http://www.ihs.com/energy-solutions/index.htm), and HPDI, Inc. 

(http://www.hpdi.com/) 

Production 

Production in the Arkoma basin has continued to increase, reaching 67 Bcf in 2007 

(Figure 31). 

 

38 Byrer, C.W., Mroz, T.H., and Covatch, G.L.: "Coalbed Methane Production Potential in U.S. Basins," Journal of 

Petroleum Technology (July 1987) 39, No. 7, 821-834 

39 U.S. Geological Survey, National Oil and Gas Assessment 

(http://energy.cr.usgs.gov/oilgas/noga/assessment_updates_2008.html) 
40

Figure 31. Arkoma Basin Production 

0

10

20

30

40

50

60

70

80

1997 1999 2001 2003 2005 2007

Bcf/Year

Sources: IHS Inc., (http://www.ihs.com/energy-solutions/index.htm), HPDI, Inc. 

(http://www.hpdi.com/), and the Energy Information Administration 

(http://tonto.eia.doe.gov/dnav/ng/ng_prod_coalbed_s1_a.htm) 

Market/Access/Environmental Characteristics 

Resource Access 

Most of the land in the Arkoma Basin area is privately owned. 

Market Access Issues 

Even before CBM wells had been drilled, extensive conventional gas production occurred 

from sands in the Arkoma basin interbedded with coal. Consequently, a widespread 

infrastructure for gas production exists in the basin. , the Arkoma Basin area would be an 

advantageous CBM production location because it currently has a network of pipelines in place 

to transport the gas produced.

Environmental Considerations 

There are plenty of recognized zones for disposing of waters that are produced by the 

extraction of the CBM in these basins.